Geochemical exploration processes were applied to characterize, analyze, identify, and correlate, 11 crude oils and five source rock samples (core and cuttings), which were recovered from oil exploratory wells within the Mesopotamian basin; this basin is considered as one of the most formative, potential, and promising basin in the Middle East. Remarkable total organic carbon (TOC) identifies good source rocks encountered from Upper and Middle Jurassic deep wells and also extracts from Upper Cretaceous Shiranish formations. Two main families recognized (family A) subsidy to subfamily (a) and subfamily (b), generated by different source rock types, and different ages has been established on the basis of biomarker. This family was generated by marine carbonate–intrashelf subbasin source rocks, occurring in Jurassic–Cretaceous–Neogene reservoir rocks in both Zagros Fold Belt and Mesopotamian basin which are geochemically similar to the extracts from the Middle–Upper Jurassic age (Sargelu and Naokelekan Formations), yielding the majority of petroleum oil and gas fields in Iraq. (Family B) of the Upper Triassic Kurra Chine Formation, shallow marine–lagoonal environment, Upper Cretaceous Shiranish formation. Shale beds of the Middle Jurassic Sargelu formations are the major sources of oil in Iraq; these strata were deposited in euxinic marine environment, and most of rock sample are highly mature, with TOC attaining 16.20 wt% and average hydrogen index (HI) of 499 with relatively low values of oxygen index (OI) and maximum temperature (T max) 446.

Bulk properties, stable carbon isotopes, whole crude Gas-Chromatography and oil mode ratios of sterane and terpanes data of analyzed samples of oil from the Cretaceous Formation reservoirs of East Baghdad oil field are from five producing wells (EB21, EB68, EB92, EB5 and EB31) from reservoirs of Zubair, Khasib, and Tanuma Formations. They are discussed with aids of characters, hopane, tricyclic terpane, isotopic delta(C)13 saturate, aromatics, and pristine-phytane diagrams. The analized oil have indicated light and medium oil in the Zubair reservoirs and heavy oil for the Khasib and Tannuma oil, with about 15% asphalt and porpherine range of 16.7-35.1 Ni and 68-117 ppm, giant reservoirs. The oil source environment and lithology are of marine algal type II and deltaic type that are non biodegraded deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation, aided by pristine-phytane and Tmax equivalent from MDR (Methyldibenzothiophene ratio) diagrams, are showing mature with Tmax 430-435 degrees C while source age assessment are taken from delta(C)13 (%) and the calculated C28/C29 sterane ratio to be of Middle and Upper Jurassic as well as Lower Cretaceous age that could be correlated mainly with the Chia Gara and Zubair Formations as well as the Middle Jurassic Sargelu Formation source rocks for oil that are accumulated in the reservoirs of Zubair, Khasib and Tannumah Formations.Source rocks are mainly Upper Jurassic-Lower Cretaceous Chia Gara Formation with contribution from the Middle Jurassic Sargelu and Lower Cretaceous Zubair Formations. The richness of the source rocks, mostly due to shale rich in TOC, and the type of kerogen is mixed type and type III. The formations have good petroleum potentiality (PP) and the OM reaches the Early of hydrocarbon generation. Oil, and gas are the most probable product, and the generated hydrocarbons can be expelled at this level of thermal maturity which is confirmed by petromod software basin modeling to suggest migration and accumulation during the Upper Cretaceous time.Hydrocarbon dynamic in East Baghdad Oil Field are performed using seismic section, logs and porosities. Model assessments of the hydrocarbon generation, migration paths and accumulation sites as well as places of enriched oil are used to assess reservoir location and suggestion for drilling sites. (C) 2016 Elsevier Ltd. All rights reserved.

Summary This study is concerned with Jurassic – Cretaceous succession of oil field called Ad’daimah (local Arabic word meaning rainy clouds and might be abbreviated to Dima field) to explore the hydrocarbon potential in the Ad’daimah structure that formed mainly by salt diaper of the pre-Cambrian Hormz Formation. The sedimentary column thickness of Jurassic comprises up to 1100m, and 500–700m of lower Cretaceous.

The main parameters of the possible source rock within Zubair Formation are satisfying, in terms of quantity, quality, and thermal maturity. Thirty-eight samples (15 cores 23 cuttings) are analyzed to determine the pyrolysis parameters as well as nine rock samples (6 core and 3 cuttings) are introduced to gas charmotagraphy/mass spectrometry (GC/MS) analysis. On the other hand, six oil samples were analyzed to determine the carbon isotopes, biomarkers, composition, and correlation. Quantitative analysis is done with GC/MS. In addition, 14 rock samples were subjected to infrared analysis. All these data are mainly obtained from Nassiriah, Gharraf, and Rafidain oil fields in Euphrates Subzone as well as from Rumaila North, Rumaila South, Zubair, and West Qurna oil fields in Zubair Subzone. Early-peak oil generation has been indicated from the Vitrinite reflectance (Ro) to the chosen samples in the Zubair Subzone (Ro maximum 0.81 %), while in the Euphrates Subzone, the maturity is indicated as immature-early oil generation (Ro maximum 0.69 %) due to shallow depths of Zubair Formation as well as the terrestrial supply of organic matters. On the other hand, the optical investigation revealed that the formation is within the mature zone dependent of color index. From the total organic carbon (TOC) values' point of view, shale intervals within Zubair Formation are generally good to excellent as source rocks, except in the lower parts, namely, the Lower Shale Member in the Zubair Subzone, which has fair amounts of the total carbon content. While the kerogen types are mainly type III gas prone, but type II/III oil-gas prone, and type II oil prone are available, which the later concentrated in the upper and lower sandstone members. The dominant type of organic matters was the amorphous organic material (AOM), which is principally related to oil prone source rock. On the other hand, the IR analysis also indicates the oil prone type II and type I kerogens in dependence on the A and C factors. The Rock-Eval pyrolysis shows that the organic geochemical properties presented an effective and/or potential source rock depending on the values of S1, S2, and S3 and their derivatives. This source rock has started the oil expulsion, where the S1/TOC values were mainly more than 0.2 mgHC/g TOC. The source-related biomarkers suggested that the reservoir oils of Zubair Formation and the source rock-extracted oils indicate the same origin, depositional environment, sulfur content, and maturity level. The depositional environment of the source rock is indicated as the anoxic, shallow marine offshore facies of the prodelta shale intervals, which is located within the multi-story sand bodies.

Summary Yamama Formation (Late Berriasian- Aptian cycle) is one of the main Lower Cretaceous carbonate promising reservoir in the Mesopotamian Basin, southern Iraq. The Yamama obviously is oil producing throughout Rumaila North, Zubair, Majnoon, West Qurna, NahrUmr, Nasiyria, Abu Khima, Rafedain, Samawa, and Luhais oil fields southern Iraq. Four crude oil samples and fifteen source rock extracts from Lower Cretaceous Yamama formation from Ratawi and other selected oil fields have been analyzed in Geomark Research Ltd in Houston-Texas using Gas Chromatography – Mass Spectroscopy (GC-MS), to get biomarkers ratio in the branched, cyclic, and aromatic fractions, and carbon e isotope analysis. In addition, thirty rock samples from the Upper Jurassic and Lower Cretaceous sequences, have been subjected to source rock analysis.

Palynomorps of mainly dinoflagellate cysts are used in this study to assess age of Middle Jurassic (Bajocian–Bathonian) Sargelu, Upper Jurassic (Upper Callovian–Lower Oxfordian) Naokelekan, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine, and Upper Jurassic–Lower Cretaceous (Beriassian–Tithonian) Chia Gara source rock Formations. Materials used for this palynological study are 85 core and cutting samples of five oil exploratory wells of Bj-1, Tk-3, Aj-8, K-109 and Tq-1 of selected North Iraqi oil fields. Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters and palynomorphs. Accordingly, Chia Gara and Sargelu Formations are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B, which comprised principally brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings and phytoclasts that could indicate affect of upwelling current. These deposits contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin’s scale of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation.

Summary Analysis of δ13 C aromatics and saturates hydrocarbons plus extracts from source rocks plots in graphical diagram as well as their δ13C% and C28/C29 ratio of source age sterane biomarkers of 300 scattered Crude oil samples have enabled this study to assess hydrocarbons grouping into families’ related to sedimentary basins in Iraq. Oil sources might be Middle Jurassic strata of Sargelu Formation in the Zagross Fold Belt of North Iraq and eastern part of Mesan Governorate with Middle Jurassic as well as Upper Jurassic/ Lower Cretaceous Chia Gara Formation in the North-East based on C28/C29 ratio of nearly 6 and 8 respectively. Mesopotamian Basin oil sources are of mainly Upper Jurassic/ Lower Cretaceous Sulaiy Formation above the Upper Jurassic lower regional seal of the Gotnia Anhydrite except were thinned and faulted with C28/C29 ratio ranges between 5– 9 that could cause mixing with Middle Jurassic Sargelu Formation oil. Middle Triassic oil in North West Iraq is recorded within Kurra Chine Formation with C28/ C29 ratio of 4 while Lower Palaeozoic oil sources are recorded in West Iraq. On the other hand, one formation may have multiple pays of Jurassic and Lower Cretaceous sources such as Zubair and Yamama Formation.

Summary Mesan Governorate in particular passes into two main basins; these are the Zagross Fold Belt Basin to the east toward the Iranian Border with continuation northward toward Diyala and Sulaimaniyah Governorates and hence contain mainly structural reservoirs. On the other hand, the second main basin is the Mesopotamian Foredeep Basin to the west toward Nasiriyah Governorate with continuation southward toward Basrah Governorate and northward toward Baghdad the capital, this basin contains more stable and thick strata that contain stratigraphic as well as structural reservoirs.

Nine oil samples of four production wells from Halfaya oil field are selected in this study from the reservoirs of Khasib, Mishrif, and Nahr Umr Formations. They are analyzed chemically for their crude oil characterization as well as isotopes and biomarkers to assess their source rock affinities. Oil biomarkers and isotope values of the analyzed samples from the Nahr Umr, Mishrif, and Khasib Formation reservoirs of Albian, Upper Cenomanian, and Lower Coniacian ages, respectively, from four selected production wells are plotted on sterane triangle, hopane diagram, tricyclic terpane diagram, pristane to phytane ratio with canonian variables, δ13C saturated and aromatic, and pristane/phytane diagrams. They have indicated source environment and lithology of marine algal type II that are nonbiodegraded and deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation are assessed by plots of oil analyzed values on the pristine/phytane diagram. Mature oil are also shown with T max equivalent of 435–440 C based on plots of methyldibenzothiophene ratio (MDR) and vitrinite reflectance of R o = 0.70–0.85 based on methylphenothrene ratio (MPI). Source age assessment are taken from δ13C (%) and the calculated C28/C29 sterane ratio which indicate Middle Jurassic age. Two structural contour maps and two seismic sections are used in this study for assessing source reservoir relations, oil migration paths from the Middle Jurassic Sargelu Formation and accumulation sites in mainly Cretaceous reservoirs. Accordingly, suggestion for risk assessments of drilling sites for hydrocarbon production could be given on the seismic section.

Mishrif crude oil is characterized by low APIgravity, high sulfur content, and carbon isotope ratio of -27.59. The composition of Mishrif crude oil is mainly aromatic. The different relation between different biomarkers indicate that the source of Mishrif crude oil is an anoxic marine carbonate mature kerogen type II, with an age of Upper Jurassic - Lower Cretaceous. Accordingly, the most probable source for this crude oil may be the Sargelu and Sulaiy Formations. The studied crude oil is non- biodegraded evidenced from chromatograms and crude oil composition of ternary diagram.

Findings of the oil source affinity for oil sample collected from shallow borehole already drilled for ground water purposes at the Sakran area, NE Haditha city, western Iraq, is performed in this study by biomarker studies with addition to the analysis of gravity map. Petroleum geochemistry study is carried out on oil sample. The terpane and sterane biomarker distributions, as well as the stable isotope values, are used for determining the validity of oil to correlate its source. The results showed that the oil belongs to the Jurassic age, with high sulfur content (2.75 %) and value of C28/C29 up to 0.75. The tricyclic terpanes values as well as hopanes indicated a source rock affinity of carbonates, whereas the pristine/phytane ratio indicated marine algal source of kerogen type II. All these information could confirm that the source rock affinity was the Sargelu Formation (Jurassic), in which their age’s equivalent to the source in East Baghdad Oil Field and Tikrit Oil Field, with a difference from the oil family near the Akkas field, located to the west of the area. Chemical analyses of water sample collected from the borehole showed the following results: TDS = 12,700 mg/l, EC = 215,900 μs/cm, pH = 6.8, DO = 28 mg/l, and temperature = 24 °C. Hydrochemical functions such as rNa/rCl (<1), (rNa–rCl)/rSO4 (<0) and rSO4/rCl (<1) indicate that the water is of marine origin, partially mixed with meteoric water. Analysis of the gravity map revealed two anomalous areas; the western one represents large anomaly with EW trend similar to the Anah graben to the north. The second one consists of many anomalies trending N–NW direction. The main local anomaly is identical with the seeps from the drilled borehole covering large area. The boundaries and trends of the main geological structures have been defined by gradient analysis procedure to the gravity data. The closed gravity anomalies with their large extensions reflect the importance of the results for further studies and promising area for oil reservoirs.

The current work investigates the hydrocarbon potentiality of the upper Jurassic–lower Cretaceous rocks in the Marib-Shabwah Basin, Central Yemen, through the Sabatayn-1 well. Therefore, palynological and organic geochemical analyses were carried out on 37 ditch cutting and 12 core samples from the well. Palynofacies analysis of the Madbi (late Oxfordian–early Tithonian) and Nayfa (Berriasian–Valanginian) Formations sediments indicates deposition of their organic-rich shale, calcareous shale and marl in middle to outer shelf environments under dysoxic–anoxic conditions, containing mainly kerogen of types II to III. However, the shales of the lower Sabatayn (Tithonian) Formation were deposited in an inner shelf environment of prevailing dysoxic–suboxic conditions, and show kerogen types III to II. Regional warm and relatively dry palaeoclimate but with local humid conditions developed near the site of the well is thought to have prevailed during deposition of the studied well sediments. The geochemical analyses of the Madbi Formation show higher total organic carbon content (TOC) than the overlying Sabatayn and Nayfa formations: it is varies between 1.2 and 7, and with average 4 wt% TOC, and the obtained S2 values (∼3–10, average 7 mg HC/g rock) indicates that the Madbi Formation is mainly good source rock. It shows a good petroleum potential of 4–11 mg HC/g dry rock, and the Rock-Eval pyrolysis indicates mainly kerogen types II to III (oil to gas prone) of hydrogen index values (132–258, and only one sample from Lam Member is of 360 and average 215 mg HC/g TOC). The thermal maturation parameters as T max (425–440 °C), production index (average 0.13 mg HC/g rock) and thermal alteration index (2 to 2+) reflected that this formation is present at margin of maturation to early mature stage oil window. So, the Lam Member (upper part) of the Madbi Formation is considered the main hydrocarbon (oil and gas) source rock in the Marib-Shabwah Basin. Accordingly, we predict that the Meem Member is an active source for gas and oil accumulations in the overlying sandstone reservoir of the Sabatayn Formation in the Sabatayn-1 well.

Analysis of δ 13 C aromatic and saturated hydrocarbons plus extracts from source-rock plots in graphical diagram as well as δ 13 C% and C28/C29 ratio of source-age sterane biomarkers of 300 scattered crude oil samples have enabled this study to assess groupings of hydrocarbons into families related to sedimentary basins in Iraq. Oil sources include Middle Jurassic strata of Sargelu Formation in the Zagros fold belt of North Iraq and eastern part of Mesan Governorate with Middle Jurassic as well as Upper Jurassic/Lower Cretaceous Chia Gara Formation in the North East based on a C28/C29 ratio of nearly 6 and 8, respectively. Mesopotamian Basin oil sources comprised mainly of Upper Jurassic/Lower Cretaceous Sulaiy Formation above the Upper Jurassic lower regional seal of the Gotnia Anhydrite except were thinned and faulted with a C28/C29 ratio that ranges between 5 and 9, which could cause mixing with Middle Jurassic Sargelu Formation oil. Middle Triassic oil in North West Iraq is recorded within Kurra Chine Formation with a C28/C29 ratio of 4, while Lower Palaeozoic oil sources are recorded in West Iraq. On the other hand, one formation may have multiple pay zones of Jurassic and Lower Cretaceous sources, such as Zubair and Yamama formations. The kerogens of the source rocks are confirmed by chemical analytical studies of pyrolysis and by microscopic studies of palynofacie types of the disseminated organic matters. PetroMod software basin modeling for hydrocarbon generation and palynomorphs for source-rock age assessments are discussed too. Oil accumulations in the reservoirs are assessed in this study using petrophysical properties to obtain hydrocarbon filling of the rocks and trapping dynamically mobile hydrocarbons in structural and stratigraphic traps in structural cross section and seismic sections. Petroleum system framework, interpreted in this study, could be used for hydrocarbon exploration and for mineral genesis of sulfur deposits through systematic studies and analysis in the proposed oil field especially when they are plotted on seismic section images for assessing the extent of source and reservoir rocks, and hence predicting hydrocarbon migration paths and finding new reservoirs and pay zones.

Microscopic and chemical analysis of 85 rock samples from exploratory wells and outcrops in northern Iraq indicate that limestone, black shale and marl within the Middle Jurassic Sargelu Formation contain abundant oil-prone organic matter. For example, one 7-m (23-ft.)-thick section averages 442 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt.% TOC. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminiferal test linings and phytoclasts, was deposited in a distal, suboxic to anoxic basin and can be correlated with kerogens classified as type A and type B or, alternatively, as type II. The level of thermal maturity is within the oil window with TAI = 3− to 3+, based on microspore colour of light yellowish brown to brown. Accordingly, good hydrocarbon generation potential is predicted for this formation. Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils and potential source rock extracts to determine valid oil-to-source rock correlations. Two subfamily carbonate oil types—one of Middle Jurassic age (Sargelu) carbonate rock and the other of Upper Jurassic/Cretaceous age—as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA and PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well MK-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of R28 steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field. One-dimension petroleum system models of key wells were developed using IES PetroMod Software to evaluate burial-thermal history, source-rock maturity and the timing and extent of petroleum generation; interpreted well logs served as input to the models. The oil-generation potential of sulphur-rich Sargelu source rocks was simulated using closed system type II-S kerogen kinetics. Model results indicate that throughout northern Iraq, generation and expulsion of oil from the Sargelu began and ended in the late Miocene. At present, Jurassic source rocks might have generated and expelled between 70 % and 100 % of their total oil.

Oil biomarkers and isotope values of the analyzed samples from the Sa’adi and Yamama Formation reservoirs of Santonian and Valanginian ages, respectively, from well Da-1 as well as Yamama Formation extracts are plotted on sterane triangle, hopane diagram, tricyclic terpane diagram, pristane to phytane ratio with canonian variables, δ 13C saturate, aromatics, and pristine-phytane diagrams and have indicated a source environment and lithology of marine algal type II that are nonbiodegraded and deposited in anoxic environments of carbonate and shale. Source maturation at the time of the oil generation is assessed by plots of oil, and the analyzed values of the Yamama source rocks on the pristine-phytane diagram indicate these to be mature with T max equivalent of 435 °C based on plots of methyldibenzothiophene ratio (MDR) and vitrinite reflectance of R o = 0.70–0.85 based on methylphenothrene ratio (MPI). Source age assessment is taken from δ 13C (%) and the calculated C28/C29 sterane ratio indicates early Lower Cretaceous age. The Yamama Formation in this study showed excellent hydrocarbon potential with extracted organic matter of up to 16,674 ppm with a total organic carbon (TOC) equivalent of 16.64 wt%. Correlation of the analyzed data from Ad’daimah field with other oil fields in the Mesan Governorate indicates the same characteristics and revealed this to be clustered in one place in all the diagrams, but the source age shows two oil families where the first is sourced from Upper Jurassic-Lower Cretaceous as in the case in the Ad’daimah field while the second is sourced from Middle and Upper Jurassic as in the case in the Halfaya field. Source-oil correlation is confirmed in this study by plots of values from the analysis of Sa’adi and Yamama oil of well Da-1 with the extracts from the Yamama-Sulaiy formations in isotopic δ 13C saturate and aromatics, calculated C28/C29 sterane ratio diagram, sterane triangle, and MPI versus R o. These showed grouping of the oil and extracts of the analyzed data into one place of depositional environment, maturation, and age characteristics that indicate a very good correlation with excellent hydrocarbon generation from the Yamama Formation that measures up to 16,674 ppm of extracted organic matter. PetroMod software basin modeling has confirmed hydrocarbon generation from the Yamama Formation under burial thermal temperature of 114–120 °C with 285–300 mg HC/g TOC for 95 % hydrocarbon transformation from the disseminated organic matters with critical point of hydrocarbon migration and accumulation at 10 million years ago. Palynomorphs have indicated ages of Valanginan-Berriassian for the Yamama Formation and Tithonian-Berriassian for the Sulaiy Formation. Marking places of source rocks and oil reservoir on seismic section across well Da-1 for the Jurassic and Cretaceous strata have shown model assessments of the hydrocarbon generation places of the Yamama Formation, migration pathways and accumulation site, as well as places of enriched oil to assess reservoir sites and suggest for risk assessments of drilling sites for hydrocarbon production from the Yamama and Sa’adi formations. On the other hand, seismic sections in Halfaya and Buzargan fields showed hydrocarbon migration from the Sargelu Formation.

Oil and gas fields in Iraq are distributed in geographic locations with giant oil fields toward the east and giant gas field toward the west of Iraq, except Diala region that have separated gas and oil fields in the north east. Farther more, their reservoirs are scattered in stratigraphic successions. On the basis of Crude oil analysis mainly by GC, GC/MS, source rock assessments mainly by pyrolysis analysis and palynofacie, structural cross and seismic sections, as well as petrophysical properties and PetroMod software basin modeling; Iraqi oil accumulations could be grouped into varieties of total or formational petroleum systems. These petroleum systems could be used for hydrocarbon exploration and for mineral genesis through systematic studies and analysis in the proposed oil field.

1D (Petromod) hydrocarbon charge modeling and source rock characterization of the Lower Cretaceous and Upper Jurassic underlying the prolific Cretaceous and Tertiary reservoirs in the Basra oilfields in southern Iraq. The study is based on well data of the Majnoon, West Qurna, Nahr Umr, Zubair, and Rumaila oil fields. Burial histories indicate complete maturation of Upper Jurassic source rocks during the Late Cretaceous to Paleogene followed by very recent (Neogene) maturation of the Low/Mid Cretaceous succession from early to mid-oil window conditions, consistent with the regional Iraq study of Pitman et al. (Geo Arab 9(4):41–72, 2004 ). These two main phases of hydrocarbon generation are synchronous with the main tectonic events and trap formation associated with Late Cretaceous closure of the neo-Tethys; the onset of continent–continent collision associated with the Zagros orogeny and Neogene opening of the Gulf of Suez/Red Sea. Palynofacies of the Lower Cretaceous Sulaiy and Lower Yamama Formations and of the Upper Jurassic Najmah/Naokelekan confirm their source rock potential, supported by pyrolysis data. To what extent the Upper Jurassic source rocks contributed to charge of the overlying Cretaceous reservoirs remains uncertain because of the Upper Jurassic Gotnia evaporite seal in between. The younger Cretaceous rocks do not contain source rocks nor were they buried deep enough for significant hydrocarbon generation.

Palynological analysis were done on 12 rock samples for Ratawi Formation from Rumailah well 131 and eight samples for the same formation from Zubair well 47, South Iraq, to extract sedimentary organic matters. Microscopic examination led to diagnose large numbers of spores, pollen, dinoflagellates (proximat, cavate, and chorate), foraminifera, melanogen, hylogen, and amorphogen. Three palynological facies were determined on the bases of percentages of sedimentary organic matter and palynomorphs from two sections. Analysis of these palynofacies clarified Ratawi Formation as deposited from environments ranging from delta and lagoon (suboxic–dysoxic) to shelf facies (anoxic near the shore–suboxic) with the presence of some layers deposited from semideep open marine environment (bathyal). Organic geochemical analysis of total organic carbon and Rock Eval pyrolysis were done to determine quantity, quality, and degree of maturation of the kerogen. Poor to medium proportion of total organic carbon of kerogen types II and III within a catagenesis stage are recorded in these rocks, and hence, poor hydrocarbon generation could be suggested for these strata.

Organic geochemical analysis and palynological studies of the organic matters of subsurface Jurassic and Lower Cretaceous Formations for two wells in Ajeel oil field, north Iraq showed evidences for hydrocarbon generation potential especially for the most prolific source rocks Chia Gara and Sargelu Formations. These analyses include age assessment of Upper Jurassic (Tithonian) to Lower Cretaceous (Berriasian) age and Middle Jurassic (Bathonian–Tithonian) age for Chia Gara and Sargelu Formations, respectively, based on assemblages of mainly dinoflagellate cyst constituents. Rock-Eval pyrolysis have indicated high total organic carbon (TOC) content of up to 18.5 wt%, kerogen type II with hydrogen index of up to 415 mg HC/g TOC, petroleum potential of 0.70–55.56 kg hydrocarbon from each ton of rocks and mature organic matter of maximum temperature reached (Tmax) range between 430 and 440 °C for Chia Gara Formation, while Sargelu Formation are of TOC up to 16 wt% TOC, Kerogen type II with hydrogen index of 386 mg HC/g TOC, petroleum potential of 1.0–50.90 kg hydrocarbon from each ton of rocks, and mature organic matter of Tmax range between 430 and 450 °C. Qualitative studies are done in this study by textural microscopy used in assessing amorphous organic matter for palynofacies type belonging to kerogen type A which contain brazinophyte algae, Tasmanites, and foraminifera test linings, as well as the dinoflagellate cysts and spores, deposited in dysoxic–anoxic environment for Chia Gara Formation and similar organic constituents deposited in distal suboxic–anoxic environment for Sargelu Formation. The palynomorphs are of dark orange and light brown, on the spore species Cyathidites australis, that indicate mature organic matters with thermal alteration index of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation by Staplin's scale.